Integration of a Gas Fired Steam Power Plant with a Total Site Utility Using a New Cogeneration Targeting Procedure

Integration of a Gas Fired Steam Power Plant with a Total Site Utility Using a New Cogeneration Targeting Procedure

Sajad Khamis Abadi1, Mohammad Hasan Khoshgoftar Manesh2, Marc A. Rosen3,
Majid Amidpour4,*and Mohammad Hosein Hamedi4
1Department of Energy Engineering, Science and Research Branch, Islamic Azad University, Tehran 775-14515, Iran
2Department of Mechanical Engineering, Faculty of Technology & Engineering, University of Qom, Qom 3716146611, Iran
3Faculty of Engineering and Applied Science, University of Ontario Institute of Technology, Oshawa+1905-121-8668, Canada
4Faculty of Mechanical Engineering, K. N. Toosi University of Technology, Tehran 19395-1999, Iran

A steam power plant can work as a dual purpose plant for simultaneous production of steam and electrical power. In this paper we seek the optimum integration of a steam power plant as a source and a site utility system as a sink of steam and power. Estimation for the cogeneration potential prior to the design of a central utility system for site utility systems is vital to the targets for site fuel demand as well as heat and power production. In this regard, a new cogeneration targeting procedure is proposed for integration of a steam power plant and a site utility consisting of a process plant. The new methodology seeks the optimal integration based on a new cogeneration targeting scheme. In addition, a modified site utility grand composite curve (SUGCC) diagram is proposed and compared to the original SUGCC. A gas fired steam power plant and a process site utility is considered in a case study. The applicability of the developed procedure is tested against other design methods (STAR?and Thermoflex software) through a case study. The proposed method gives comparable results, and the targeting method is used for optimal integration of steam levels. Identifying optimal conditions of steam levels for integration is important in the design of utility systems, as the selection of steam levels in a steam power plant and site utility for integration greatly influences the potential for cogeneration and energy recovery. The integration of steam levels of the steam power plant and the site utility system in the case study demonstrates the usefulness of the method for reducing the overall energy consumption for the site.

integration, steam power plant, site utility, cogeneration, optimization

1 INTRODUCTION

Chemical processes usually require steam at various pressures and temperatures for heating and non-heating purposes. In order to provide the steam required, the designer has to decide to provide steam under the extreme condition and then let it down to different levels or produce steams separately in separate boilers. Many industrial processes operate within total sites [1-3], where they are serviced and linked through a common central utility system. This utility system meets the demands for heat and power of individual process units via indirect heat integration. However, greater benefits in terms of energy and capital cost can be obtained by considering the entire site. Total site integration addresses the task of optimizing each process and the utility system in the context of the overall site [4]. An important task in utility system design is targeting fuel consumption and shaft work production ahead of design.

A number of models have been proposed for the preliminary estimation of cogeneration for utility systems using steam turbines. Dhole and Linnhoff [5] proposed an exergetic model based on site source-sink profiles. Raissi [3] proposed a temperature-enthalpy model based on the Salisbury approximation [5], assuming that power is linearly proportional to the difference between the inlet and outlet saturation temperatures. Mavromatis and Kokossis [6] introduced the turbine hardware model (THM), a non-linear model based on the principle of Willans’ line, to incorporate the variation of efficiency with turbine size and operating load. Harell [7] introduced a graphical technique that utilizes the concept of extractable power and header efficiency to establish cogeneration potential, and Varbanov et al. [8] improved the turbine hardware model. Sorin and Hammache [4] developed an exergetic model based on thermodynamic insights for the Rankine cycle, showing that power is not linearly related to saturation temperature differences. Mohan and El-Halwagi [9] developed a linear algebraic approach based on the concept of extractable power and steam main efficiency. Medina-Flores and Picon-Nunez [10] presented a modified thermodynamic model by taking advantage of the THM. Bandyopadhyay et al. [11] developed a linear model based on the Salisbury approximation [5] and energy balance for steam mains. Ghannadzadeh et al. [12] presented a new shaft work targeting model, named the iterative bottom-to-top model (IBTM). Kapli et al. [13] introduced a new method to estimate cogeneration potential for site utility systems by a combination of bottom-up and top-down procedures.

The optimal integration of a steam power plant and a site utility system remains challenging withthese approaches and improved methods are needed. This paper seeks to address this need, and its aim is to find the optimum integration of a steam power plant and a site utility system. With this objective in mind, a new cogeneration targeting model is developed.

2 METHODOLOGY

A new procedure for integration of a power plant with a total site for a given site utility system is proposed. The procedure includes following steps.

Step 1 The pressure, temperature and steam generation and demand of each steam level of the site utility system is identified based on the requirements of the total site.

Step 2 A standard steam power plant is considered in a case study for integration with the site utility. Thermodynamic and economic analyses are performed, and the specifications of each stream and the main parameters of the proposed power plant are determined.

Step 3 Incoming streams from the power plant with the same pressure of site utility mains (from bleed steam) are identified and the flow changes that contribute to meet the target are examined. In this regard, the extracted steam from steam turbine is a candidate. However, the steam conditions must be same as the requirements of the steam levels of the site utility.

Step 4 The heat load of incoming streams from the power plant are calculated.

Step 5 The total sink and source profiles are generated. In this step, sink and source profiles are plotted for the site utility for a base case and for the site utility by adding incoming streams from the power plant. The total site profile (TSP) is constructed from the grand composite curves (GCCs) of individual process units for the new design and it is constructed from the individual process loads within each of the utility heat exchangers for the retrofit design [Fig. 1 (a)] [12, 14, 16]. The targets are set for site cooling requirements starting with the highest temperature cooling utility. Also, to set the targets for heating requirements, the lowest temperature heating utility is first maximized [Fig. 1 (a)]. Fig. 1 (b) shows the site composite curve (SCC) [2] for this case as the site is pinched. The residual heating requirement is satisfied using very high pressure (VHP) steam generated in the boilers, while the residual heat is rejected via cooling water (CW) [Fig. 1 (b)] [12]. Removing the site composite curves and keeping only the steam profiles [Fig. 1 (c)], all the temperature intervals of the steam profiles are shifted to the left side starting from VHP to CW, which results in the site grand composite curve (SGCC) [Fig. 1 (d)] [12, 14, 16].

Step 6 The site utility grand composite curve (SUGCC) is generated. The proposed methodology uses the SUGCC, which represents another form of the site composite curves [14]. The SUGCCs are obtained from the site composite curves by representing temperature-enthalpy axes in each steam main by its saturation temperature and steam generation and usage loads, respectively, from the source and sinks profiles of the site composites. The differences between steam generation and steam usage set the very high pressure demand or the supply heat available at each main.

Figure 1 TSP (a), SCC (b), steam profile (c), SGCC (d), SUGCC (e), cogeneration potential (f) for a pinched site and cogeneration potential (g) for a site violating the minimum targets [12]

Figure 2 Schematic of the utility system layout on an SUGCC

The SUGCC is constructed as the heat recovery across the site is removed and only the part of steam profile interacting with site utility system is retained [Fig. 1 (e)], following the approach of Ghanadzadeh et al. [12-14]. As Fig. 1 (e) relates to the location in a site that is pinched, this is only one possible setting with the maximum heat recovery, minimum heat rejection to the CW, and minimum heat demand from the boilers. However, it is not necessarily the optimum setting if the cogeneration potential [Fig. 1 (f)] [12, 16] is also taken into account. This point can be observed by considering the SUGCC shown in Fig. 1 (g), which is set such that heat recovery is not maximized. This means that an extra quantity of fuel is fired in the boilers and an extra quantity of heat is rejected to the CW [12, 14, 16]. However, the larger area between the steam profiles implies a greater cogeneration potential. Generally, more heat recovery corresponds to less power generated and less fuel required. However, the amount of overlap between the steam profiles is a degree of freedom available to the designer [16]. Detailed descriptions of total site analyses, grand composite curves and total site profiles are presented elsewhere [3, 16]. Finally, the SUGCC for base and integrated case are plotted.

Step 7 Initial estimations are made for the boiler superheat temperature.

Step 8 The minimum required flow rate from a steam generation unit and the levels of superheat at each steam main are calculated based on the heat loads specified by the SUGCC.

Figure 2 shows a schematic of the utility system layout on a SUGCC diagram, where i is equal to 1, 2, 3 and 4 for very high pressure (VHP), high pressure (HP), medium pressure (MP) and low pressure (LP) steam mains, respectively. There is an expansion zone between two steam mains. Zones are indexed by Z starting from the top, i.e., Z=1 denotes the VHP-HP, and one single steam turbine is placed in each zone.

Figure 3 shows a thermodynamic expansion of steam at two different pressures on a temperature-entropy diagram. Step1S-2S represents isentropic expansion, an ideal case with no irreversibility due to such factors as mechanical friction and heat losses. Step1S-2S′ is a better representation of what happens in reality. The outlet of the turbine is shifted to the right, which indicates an increase of entropy (state of disorder) caused by losses [17]. The isentropic efficiency represents the ratio of the enthalpy difference of step1S-2S′ to that of step1S-2S.

Figure 3 Thermodynamic expansion of steam at two different pressure levels on a Temperature-Entropy diagramP1—turbine inlet pressure; P2—turbine outlet pressure

Table 1 Regression coefficients used in the isentropic efficiency expression [8]

Figure 4 Mass load balance for ith steam main [18]

The isentropic efficiency is a function of the load and, for fixed values of flow rates, it will be better to consider the highest efficiency using turbines, for which the calculated flow rate will be the full load. In this study, the thermodynamic model of Varbanov et al. [8] is employed to estimate the isentropic efficiency (ηis) as follows

where A and B are constants dependent on turbine, calculated by

where a1, a2, a3and a4are the constants coefficient. values of these constants are given in Table 1 [8].

At the boiler exit, for a given steam pressure and temperature, the enthalpy can be obtained with the aid of steam tables. The actual input enthalpies of the steam mains are usually provided from the calculations for the previous steam main. Then, the input isentropic enthalpy of steam main in the superheated region can be obtained, and the efficiency is calculated. The actual enthalpy, which serves as the input enthalpy for the next zone, is then calculated using the isentropic enthalpies and efficiency:

In this study, the superheat temperature at each steam level is calculated with an iterative procedure based on a certain desirable amount of superheat in the LP steam main. This superheat needs to be set to 10 to 20 °C [16]. If the degree of superheat in the resulting LP steam main is less than that required, the operating condition of VHP steam is updated and the calculation is repeated until superheated conditions for the LP steam main are acceptable.

The mass flow rate of steam expanding through the Zth turbine (mZ) can be calculated by the mass balance forith steam main [15] as follows, as shown in Fig. 4.

HereGNEim denotes the flow rate of steam generated by the process andDEMi

m is the flow rate of steam demanded by the process, both of which can be calculated as follows [15]:

Here hf,idenotes the enthalpy of the saturated liquid at the pressure ofith steam main. Also, at a given level,

where Qnet,idenotes the net load, hiis the steam main isentropic enthalpy, and hfis the saturated liquid enthalpy.

The initial mass flow rates passing through each zone are estimated, assuming isentropic expansions throughout the levels via Eq. (9).

Step 9 The efficiency is modified for improved accuracy using the following expression

Figure 5 Schematic of a modified SUGCC1—VHP; 2—HP; 3—MP; 4—LP

Step 10 For the given steam levels, the values for hiandNETim are revised for better accuracy.

Step 11 For subsequent iterations to convergence, the steps are repeated until the stopping criterion is achieved according to the following:

Step 12 When the first loop of algorithm terminates, the LP superheat temperature is checked. If it falls below the allowed minimum, the superheat temperature of the boiler is increased and the steps are repeated until the desired amount of superheat is achieved in the LP steam main.

Step 13 The shaft work production in each zone of the site utility is calculated as follows.

Step 14 Final SUGCC is generated, with values of following parameters determined: final steam temperature at each level, mass flow rate through the boiler, the steam temperature that must be generated in the boiler, the steam temperature, mass flows and the final temperatures of each steam mains.

Step 15 The modified SUGCC is obtained, as shown in Fig. 5. The left right of horizontal axis demonstrates the temperature-enthalpy diagram of the site utility and the other side is same as the original SUGCC. The proposed modified SUGCC representation illustrates the real condition of each steam mains of the site utility in a temperature-entropy (T-S) diagram. Also, the steam generation and use, steam heat demand and shaft work production of the site utility are shown in the other side of this diagram.

Figure 6 shows an algorithm of the new procedure.

3 COMPUTER PROGRAM

A computer program is developed in this study for

(1) Simulation of the thermodynamic steam cycle;

(2) Analysis of total site (single purpose and integrated plant);

(3) Targeting of steam and power generation in site utility system (single purpose and integrated plant);

(4) Economic evaluation;

(5) Integration of site utility with the steam power plant.

The program uses following input data:

(1) standard pressure (P0) and temperature (T0);

(2) fuel compositions and costs;

(3) air composition and relative humidity;

(4) load conditions;

(5) gross shaft power of steam turbine;

(6) shaft work consumption in pumps;

(7) mass flow rate, pressure and temperature for fluid streams at the inlet and outlet of each component;

(8) initial investment of capital cost, interest rate, salvage value factor;

(9) configuration of feed water heaters;

(10) process site utility data;

(11) economic data.

Figure 6 Algorithm of the new procedure

With these input data, the program can be used to calculate the number of moles of combustion products, the adiabatic flame temperature, and the enthalpy (MW) and entropy (MW·K?1) rates for fluid streams at various states. Using the values of these properties, we calculate the net flow rates of various exergies and entropies, the exergy efficiencies of the components and the lost exergy in each component. The heat transfer rate from a component is calculated to satisfy the exergy balance for the component.

Also, this code can generate TSP, SUGCC and modified SUGCC, and it can be used for integrating the steam power plant with the site utility.

4 CASE STUDY

We consider a 315 MW gas fired conventional steam power plant (similar to the RAMIN power plant that is located in southwest Iran in Ahvaz city). A flow diagram of this plant and its steam turbines is shown in Fig. 7. The numbers indicate streams in power plant cycle. In this case study, we consider the optimal design of a 315 MW gas fired steam power plant integrated with the site utility.

The net plant efficiency based on low heating value (LHV) is about 38.5% (assuming a single purpose plant). The fuel flow can be modified in the integrated plant, but the net power generation by the power plant is fixed at 315 MW as a constraint.

The assumptions used in this study are based on the optimal design of a 315 MW power plant for integration with the site utility system. In the base scenario, the streams extracted from steam turbine enter the feed water heaters. In the integrated plant, some of steam extracted from the steam turbines is fed to the process directly. The steam power plant in the coupled scenario operates at full load and the mass fuel is increased correspondingly. With this approach, there is no loss of power generation in the power plant section in the coupled plant.

The schematic of site/source composite curve of the total site and the site utility system of a process plant is illustrated in Fig. 8, indicating the steam generation and use at each of the steam levels and the total site profile. A schematic of the site utility for thebase case is provided in Fig. 9.

Figure 7 Schematic of a conventional gas fired steam power plant [1]FWH—feed water heater; HPT—high pressure turbine; IPT—intermediate pressure turbine; LPT—low pressure turbine; C—condenser; G—generator; CP—condenser pump; DA—deaerator

Figure 8 Site source and sink composite curve (site utility-base case)

Property values at various state points in the 315 MW plant under full load conditions are shown in Table 2. The required steam properties for the site utility are determined (see Table 3). Table 4 indicates the steam generation and steam use by the site utility for the base condition, as demonstrated in total site profile (Fig. 8).

5 RESULTS

Figure 10 shows the SUGCC of site utility of total site for the base case using the new procedure described in this article. Also provided for the SUGCC are the shaft power production by each zone, the steam generation and use for each zone, the fuel requirement, the steam temperature at the boiler outlet and the real condition of each steam main in site utility.

The steam requirements of the site utility system at three pressure levels (VHP, MP and LP) are provided by bleed steam from the steam power plant. In this regard, the three feed water heaters are removed and the steam extracted from the steam turbines (streams 103, 104 and 107) enters the site utility at the same steam levels. A schematic of the integrated plant is shown in Fig. 11. The exiting stream properties for the power plant are indicated in Table 2. The total site profiles (TSPs) under the integrated condition areshown in Fig. 12.

Figure 9 Schematic of site utility system of a process plant (base case)

Table 2 Properties at various state points in a 315 MW plant under full load conditions①

We determine the steam requirements of the site utility in the coupled plant (see Table 5) and the steam generation and use in the integrated plant for the site utility (see Table 6).

Figure 13 shows the SUGCC and Fig. 14 shows the site utility for the integrated plant. The cogeneration potential of the site utility for the coupled plant is illustrated in Fig. 15. The fuel requirements and steam generation at the boiler in the site utility are decreased in the integrated plant relative to the base case. Also, the power generation by the site utility is decreased, and the VHP steam demand of the integrated plant for the site utility is decreases by 65%.

Figure 10 SUGCC of the steam network (base case)

Figure 11 The scheme of the steam power plant (integrated)FWH—feed water heater; HPT—high pressure turbine; IPT—intermediate pressure turbine; LPT—low pressure turbine; C—condenser; G—generator; CP—condenser pump; DA—deaerator

Figure 12 Site source and sink composite curve (integrated plant)

Table 3 Steam requirements for site utility (base case)

Table 4 Steam generation and use (base case)

Table 5 Steam requirements of the site utility (integrated)

Table 6 Steam generation and use (integrated)

The modified SUGCC of the steam network is provided in Fig. 16. The right side shows a thermodynamic expansion of steam in the steam network on a temperature-entropy diagram. Point 1 shows the actual temperature of the steam at the outlet of the boiler and points 2, 3 and 4 show actual temperatures of steam at the outlets of the VHP-HP, HP-MP and MP-LP turbines, respectively.

Taking into account these thermodynamic insights into cogeneration in general and the Rankine cycle in particular, we propose a new representation based on a modified SUGCC in order to visualize it on the same diagram. Thus, fuel consumption, steam generation in the boiler, shaft work production, cooling targets and actual states of steam mains are obtained. Hence, the present work examines the effect including both sensible and latent heating of steam in the right side of proposed curve.

The economic evaluation for the power plant section is presented in Table 7. The break-even electricity price of the coupled plant is decreased by 0.0301 USD·kW?1·h?1compared to the base power (uncoupled) plant. In addition, the operating cost is increased due to greater fuel consumption in the integrated plant. Three feed water heaters are removed for the integrated plant, and steam is delivered from the steam power plant section to the site utility, and the inlet steam temperature in boiler is reduced while additional fuel is needed to generate the same 315 MW power in the power plant section. The total annual profit of the plant is 115.67×106USD for the base case, while 130×106USD for in the integrated plant. In the integrated plant, the power plant generates two main products: power and process steam. However, the total investment for the integrated plant (222.81×106USD) is more than that for the base case (216.35×106USD) due to increased operating costs. The payback period is calculated as follows:

Payback period (a)=

total investment (USD)/profit (USD·a?1)

As shown in Table 7, the total investment for the power plant for the base case is 216.135×106USD and the total profit is 115.67×106USD·s?1; so the payback period is 1.9 years for the power plant in the base case. The total investment in the power plant (integrated) is 222.81×106USD and the profit due to the sale of steam and electricity is about 130×106USD·a?1, yielding apayback period for the power plant (integrated) of 1.7 years.

Figure 13 SUGCC of site utility (integrated plant)

Figure 14 Total site utility system (integrated plant)

An economic evaluation of site utility (integrated) is shown in Table 8. The annual fuel cost in the integrated site utility is decreased by 34% relative to the base case because the fuel consumption decreases sig-nificantly when steam requirements are satisfied by incoming streams from the power plant. In addition, power production by the site utility is decreased by 65% relative to the base case and the total investment is reduced by 33%. The total profit of site utility in integrated plant is 170.26 ×106USD·a?1and the total annualizedcost of the site utility is decreased by 24%.

Figure 15 Cogeneration potential obtained by the new procedure (integrated plant)

Figure 16 The modified SUGCC of steam network (integrated plant)1—VHP; 2—HP; 3—MP; 4—LP

Table 7 Economic evaluation of the integrated power plant with the site utility (power plant section)

Table 8 Economic evaluation of integrated site utility with power plant (site utility section)

Table 9 Economic evaluation of the separate and integrated plants

The economic evaluation of the separated plants accounts for the overall separate site utility and the separated power plant. The overall integrated plants (site utility power plant) are shown in Table 9. The total annualized cost of the coupled plant is decreased by 3.2% compared to the overall separated plants. The total investment in the separated plant id reduced by 5% and the total benefit is increased by 2.5% for the coupled plant. The operating cost, the capital cost and the total annualized cost related to the overall coupled plants are reduced relative to the overall separated plants. Also, the payback period of the total plant (integrated) is less than one year. The results demonstrate that the integrated plants obtained by the new procedure are more beneficial than separate plants (i.e., the base case).

6 CONCLUSIONS

The optimum integration of a steam power plant as a source and a site utility system as a sink of steam and power is investigated. A new cogeneration targeting procedure is developed for the integration of a steam power plant and a site utility of the process plant with a high level of accuracy. The new model is utilized for the optimum integration of a steam power plant and a site utility system. The results indicate that the integration is a good option from thermodynamic and economic viewpoints. The integration reduces the total annualized cost of the coupled plant compared with separate plants. A 315 MW gas fired conventional steam power plant and a site utility system are assessed in case study, showing that the optimum integration is economically beneficial.

NOMENCLATURE

H enthalpy, kJ

h specific enthalpy, kJ·kg?1

P pressure, Pa

Q heat load, MW

s specific entropy, kJ·kg?1·K?1

T temperature, °C

W shaft work, MW

Z expansion zone

Superscripts

act actual state

DEM process steam demand

f liquid state

GEN process steam generation

i steam main

net net heat

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2012-11-05, accepted 2013-02-01.

* To whom correspondence should be addressed. E-mail: amidpour@kntu.ac.ir